Welcome to the APA Corporation Second Quarter 2021 Earnings Results Conference Call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask a question during the session, you'll need to press star one on your telephone. Please be advised that today's conference is being recorded. If you require any further assistance, please press star zero. I will now hand the conference over to Gary Clark, Vice President of Investor Relations. Please go ahead. Good morning. Thank you for joining us on APA Corporation's second quarter 2021 financial and operational results conference call. We will begin the call with an overview by Chief Executive Officer and President, John Christmann. Stephen Riney, Executive Vice President and Chief Financial Officer, will then provide further color on our results and 2021 outlook. Tracey Henderson, Senior Vice President of Exploration, Clay Bretches, Executive Vice President of Operations, and Dave Purcell, Executive Vice President, Development, will also be available on the call to answer questions. Our prepared remarks will be approximately 12 minutes in length and the remainder of the hour allotted for Q&A. In conjunction with yesterday's press release, I hope you've had the opportunity to review our second quarter financial and operational supplement, which can be found on our investor relations website at investor.apacorp.com. Please note that we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. Consistent with previous reporting practices, adjusted production numbers cited in today's call are adjusted to exclude non-controlling interests in Egypt and Egypt tax barrels. Finally, I'd like to remind everyone that today's discussions will contain forward-looking estimates and assumptions based on our current views and reasonable expectations. However, a number of factors could cause actual results to differ materially from what we discuss today. A full disclaimer is located with the supplemental information on our website. With that, I'll turn the call over to John. Good morning, thank you for joining us today. In my prepared remarks, I will review APA Corporation's second quarter results and comment on our outlook for the remainder of 2021. The company is making good progress on several key initiatives. We generated nearly $400 million of free cash flow during the second quarter, and at June 30, held approximately $1.2 billion of cash, which will be used primarily for debt reduction. In May, we reached an agreement in principle with the Egyptian Ministry of Petroleum and Egyptian General Petroleum Corporation to modernize the terms of our production sharing contracts. The final draft of which has now been completed and will move to Egyptian Parliament for ratification in the fall, and then to the president for his approval. We are pleased with the progress thus far and believe that this modernization will return Egypt to the most attractive area for capital investment within our portfolio and will put Egyptian oil production back on a growth trajectory. In Suriname, as announced in our press release last week, we drilled a successful appraisal well in the Sapakara area, moving us closer to our goal of sanctioning the first commercial oil development. We are generating strong results from our DUC completion program in the Permian, and during the second quarter, we closed two smaller-scale Central Basin Platform asset sales as we continue to optimize our portfolio. On the ESG front, APA continues to deliver on our key initiatives and safety metrics. Most notably, at the beginning of the year, we established an ambitious goal of eliminating routine flaring in the U.S. in 2021, and I am pleased to announce that we will achieve this goal in the third quarter. This is the result of adding compression where appropriate, setting clear expectations and rules in the field, and improving hydrocarbon processing at location. These efforts have also helped to drive down our flaring intensity, which is tracking well below our goal of less than 1% for the year. We are also making great progress on our water initiatives. In the U.S., we are currently at 3% fresh water usage, which is also well below our goal of less than 20% for the year. Turning now to operations. Total adjusted production exceeded our guidance in the second quarter, with the U.S. benefiting from better-than-expected performance throughout our Permian Basin DUC completion program. This more than offset lower international volumes, where higher oil prices impacted Egypt cost recovery volumes, and we experienced extended operational downtime in the North Sea. Upstream capital investment was below our guidance for the quarter, primarily due to timing, while LOE was slightly above expectations. Our full-year outlook for these items remains unchanged. In the U.S., we placed a total of 27 wells online in the Permian, including five at Alpine High. In aggregate, these wells are significantly exceeding internal expectations, driven by a combination of optimization initiatives. This effectively completes our backlog of Permian DUCs, so you will see fewer well connections during the second half of the year. You will also see Permian production come down a bit in the second half of the year, as our current pace of drilling and completions is not sufficient to offset the initial declines from the DUC completion program. As previously planned, we added a second Permian Basin rig in late June, which will enable a steadier pace of completions. In the East Texas Austin Chalk, we drilled three operated wells and are pleased with the results thus far. We are evaluating the addition of a third drilling rig in the U.S. as previously noted, which would put us on a path to sustained oil production. Given strong oil prices and the recent improvement in natural gas and NGL prices, all of our U.S. asset areas are attractive candidates for this rig addition. In Egypt, we have increased our rig count to eight and continue to build high-quality inventory across our expanded acreage footprint. Facilities expansion constrained our ability to connect wells in the first half of the year and contributed to a decline in gross production during the second quarter. As we wrap up our facilities work, well connections will increase significantly in the second half of the year, and gross production will begin trending up. In the North Sea, we continue to operate one floating rig and one platform rig crew. During the second quarter, production was impacted by compressor downtime, extended platform turnaround work, and third-party pipeline outages. Some of this carried over into July, and when combined with planned maintenance turnarounds at Beryl, will lead to only a modest production increase in the third quarter. Once we conclude this heavy maintenance period, production volumes in the North Sea should return to more normalized levels in the fourth quarter. In Suriname's Block 58, we are running two rigs. Upon completion of drilling operations at Sapakara, the Maersk Valiant will mobilize to the Bonboni exploration prospect approximately 45 km to the north. Following Bonboni, the Valiant will return to flow test the Sapakara South- 1 well. Drilling activities continue at the Keskesi South- 1 appraisal well with the Maersk Developer. On Block 53, where APA is the operator and 45% working interest owner, we recently signed a contract with Noble Corporation to secure a drill ship that will commence exploration operations in the first quarter of 2022. Before turning the call over to Steve, I would like to comment on our outlook for the remainder of the year. Oil prices year-to-date have averaged well above our original budgeted level of $45 WTI, and more recently, gas and NGL prices have also begun to significantly exceed budgeted levels. This has created a very welcome amount of incremental free cash flow and will enable substantial progress on debt reduction this year. More importantly, our 2021 capital program will remain unchanged at $1.1 billion, even if we decide to add a third rig in the U.S. later this year. In June, we opened our Houston and Midland offices and began welcoming back the majority of our office staff as permitted by regional guidelines. It has been great to see more in-person collaboration in settings that we took for granted prior to COVID-19, and we will remain diligent with our protocols to keep employees safe. With that, I will turn the call over to Steve Riney, who will provide additional details on the second quarter and our 2021 outlook. Thank you, John. As noted in our news release issued yesterday, under generally accepted accounting principles, APA Corporation reported second quarter 2021 consolidated net income of $316 million or $0.82 per diluted common share. These results include items that are outside of core earnings. Excluding the second quarter impacts of divestiture gains, movements in our tax valuation allowance, mark-to-market derivative losses, and other smaller items, adjusted net income was $266 million or $0.70 per share. Most of our financial results were in line or better than guidance this quarter, with just a few minor exceptions. As we've discussed in the past, we continuously review our portfolio for the right time to monetize assets that no longer compete for funding. In the second quarter, we closed the sales of two such packages in the Central Basin Platform. These were mostly lower-margin conventional waterflood assets, which were producing roughly 2,500 barrels of oil per day. Proceeds from the sales were $178 million. As we look forward to the rest of 2021, we are updating some of our full-year guidance items. We are effectively increasing U.S. production guidance by 4,500 BOEs per day and decreasing international adjusted production guidance by 14,500 BOEs per day compared to the midpoint of the previous respective ranges. This net decrease of 10,000 BOEs per day for the full year reflects the strong underlying performance of our U.S. assets, but it also captures the impact of a few offsets. The unplanned operational downtime in the North Sea, the impact of higher oil prices on Egypt cost recovery barrels, and the recent Permian Basin asset sales. We are reducing full-year DD&A guidance by $125 million, which reflects a combination of price-related reserves additions and the impact of our changing production mix with lower North Sea volumes and higher U.S. volumes. Finally, other than an increase to our expected U.K. tax expense due to strong commodity prices, there are no material changes to the remainder of our guidance for the year. On a longer-term perspective, one of our most important strategic goals is to return to investment-grade status, which will require a significant reduction in debt. In the near term, progress towards this goal takes priority over the capital program, which today is still below a sustaining level of development capital. In other words, we are willing to under-invest slightly in the short term to build balance sheet strength and financial resilience for the longer term. We entered 2021 anticipating a multi-year process of debt reduction. With this price environment, we're making significant progress more quickly than we thought possible. In the first half of the year, at an average WTI price of $62, we delivered upstream-only free cash flow, which excludes dividends received from Altus Midstream of $860 million. Assuming current strip prices for the second half of 2021, upstream-only free cash flow for the full year is expected to be around $1.7 billion. The vast majority of this cash will be available for debt reduction. The rating agencies will ultimately decide when we return to investment grade, but we will clearly make significant progress in 2021. With meaningful progress on debt in sight, we would remind everyone that we have a strong portfolio of investable inventory, and it would be prudent to at least increase development capital to a production-sustaining level. We estimate this would require around $1.2 billion of annual investment versus the $900 million we are investing in development capital this year. At this investment pace, and assuming prices remain flat with 2021, as we look out to the next several years, APA is capable of generating upstream-only free cash flow of $1.6 billion-$1.7 billion annually. This is all based on our current portfolio of assets. To highlight what the current portfolio can deliver, this analysis assumes no further investment or future benefit from Suriname and no free cash flow uplift associated with Egypt modernization, which is still pending. With that, I will turn the call over to the operator for Q&A. Your first question comes on the line of Doug Leggate with Bank of America. Thank you. Good morning. Are we still morning? Yeah, we are. Good morning, everybody. Good morning, Doug. One for Steve and one for you, John, if that's okay. Steve, thank you, first of all, for clarifying the more than $1 billion of free cash flow. That's much appreciated. The question I have is sustainability of that. The key thing for us is the value of the base business is how long you can sustain that cash flow. You said for a significant amount of time. Can you put some parameters around that so we can kind of back into what the market isn't paying for? I've got follow-ups. Yeah, Doug, let me actually put some parameters around the whole $1.6 billion-$1.7 billion of free cash flow that I talked about in my prepared remarks. John said, it gets confusing because they're the same numbers, John talked about 2021 being $1.7 billion of free cash flow, that's based on first half actual prices plus the second half strip. That is our internal, most current outlook for the business, for the full year. In 2022, we say $1.6 billion-$1.7 billion of free cash flow, that is sustainable for a run of years. We can talk about that a bit. I'd put two caveats on that. Number one, we're not attempting in any way to give guidance for 2022 and beyond at this point in time. That's a hypothetical case, but I want people to understand that that's a very realistic case. We know our inventory today better than we've ever known it. We've put together a realistic case based on what we would actually invest in the current price environment. As I said in my remarks, it is focused on the current portfolio. We've kind of chosen to eliminate the noise associated with Suriname. Doesn't have any future Suriname CapEx, no future Suriname production or free cash flow. Just to be clear, we don't want that to come across as any reflection on our feelings about Suriname, because that doesn't reflect that at all. The prices that we used in that case are exactly the same as the 2021 prices. I didn't want those to affect comparability of the results. The CapEx, as we know, 2021 is $1.1 billion. In our hypothetical case for 2022 and beyond, it's $1.2 billion. There's a difference, though. The $1.1 billion includes $200 million of exploration spend, which is mostly focused on Suriname exploration and appraisal. There's only $900 million of development capital in there. The $1.2 billion for 2022 is all development capital. A number slightly lower than that $1.1 billion is sustaining capital development or capital spending. That was when we were talking about sustaining oil production volume. The case that we've put together now, the $1.2 billion sustains BOEs on a per day basis. It actually is full production sustaining for a run of years. That's adding capital mostly to Egypt and to the U.S. Under this case, there's a slight decline in volume from 2021 to 2022 on an annualized basis, it's sustained from 2022 forward. Some people might be wondering, okay, you're spending $100 million more of CapEx and you have a lower volume, but free cash flow is roughly the same from 2021 to 2022. How do you do that? First, there's debt paydown assumed in that, so there's less interest expense because we are going to pay down somewhere in the neighborhood of $1.5 billion of debt, a little more than that, including what was on the revolver at the beginning of the year. The other thing that people may not fully appreciate is that the forward look, our production mix is changing. The spending will create a decline in gas volume and growth in oil volume. Again, prior case we talked about was a lower capital because it was just sustaining oil volume. This one's sustaining total volume, but growing oil relative to gas. Again, a reminder, that doesn't include anything in there for Egypt PSC modernization, which is going to be meaningful. The specific question that you had about how long this is sustainable, if we want to get into the inventory, I'd let David Purcell take that, and I'll give him a chance to make a comment here quickly. When I say for a run of years, I'll stick with the comment I made last time you asked me this question, Doug, and that is, this is at least for 5-10 years that we can see out into the future. Dave, you have anything to add? I would just confirm that it's in that kind of 10-year window, well beyond five years, and once you get beyond 10, it's hard to think about anybody paying for that inventory. It has absolute sustainability to it. Well, guys, thanks for the detailed answer. I really appreciate that because that's kind of what I was really trying to get to. I love the tip of the hat to Egypt could be significant. I'm guessing you're not going to answer that question, I'm going to go to Stephen and John, if you don't mind. Well, you saw what we said about this. It seems to me that if you're 2.5 mi away with pretty much the same thickness on the formation and your oil target in Sapakara, you're going to start to get some idea of the tank size. I will let you know that we had a chance to speak with the head of Staatsolie, who talked about this as being "massive." I wonder if you could just offer any thoughts on resource scale at this point, and maybe a little bit of an explanation as to why not flow test it at that time, and why do you have to come back to it? I'll leave it there. Thanks. No, Doug, I appreciate the question. As we said, we have not flow tested Sapakara South. Unfortunately, just to clarify, the testing equipment on the Maersk Valiant is damaged, and that's why. Otherwise, we'd be flow testing that thing now. It's going to take some time to repair that equipment, and that's why the ship's going to sail on up to Bonboni and get onto the exploration well that we're excited about. We need flow tests there, and we're in the middle of appraisal. We have not put out volumes yet. Clearly, we're fine-tuning things and working with things. We've talked about this being an important step towards potentially an FID, but it's just a little bit premature to get into areas and those things until we gather a lot more data. We'll do that as we continue to appraise and analyze what we've collected. We're clearly excited about it. Having 30m of one blocky sand that's full of base, high quality is the type of thing that you can build around because you've got your H there. There's a lot more to do here and a lot more to appraise. John, are we out to lunch on our tank model, 0.5 billion barrels? Repeat that, Doug. You cut out on me, Doug. I did not hear. Sorry. Are we out to lunch on our tank model to suggest order magnitude with no oil water contact, you could be sitting on half a billion barrels on that prospect? I'm just not going to comment at this point. We've got more appraisal. I appreciate the question, and I'm going to stick to where we are. It's early, we're appraising, but we're clearly excited about it. I'm not going to comment on your question there. Can't blame me for trying. Thanks, fellas. Appreciate it. Yep. Not at all. Your next question comes from the line of John Freeman with Raymond James. Good morning, guys. Good morning, John. The first question, just wanted to clarify 1 thing on Egypt. If you had the five rigs last quarter, you're now running eight rigs. When we sort of think about the PSC being approved, and obviously you've been vocal and again on this call about once it's approved, that's going to see an increase in activity. I'm just trying to make sure that I'm using the right baseline so that the incremental five rigs to eight rigs. I know there was always some incremental activity planned the second half, but is the eight rigs the baseline that we're supposed to use ahead of PSC, or was there any maybe additional rig or two that was added sort of in anticipation of the PSC being approved? Just want to make sure when I'm thinking about 2022 modeling that I'm using the right starting point. Well, clearly we're taking some steps that we've agreed with them. In terms of your baselines for capital and those items, I think we're in the fairway to stay where we are. Dave, anything you want to add? John, I think it's a good question. We've said, I think, hinted in the past that we think we need eight to nine rigs to keep oil production flat in Egypt. I think you'll see the eight rigs get us pretty close to that. Then we'll see where we go after modernization. I think John and Steve both talked about post-modernization could put us on a path to grow in Egypt. Eight rigs sustained, that I think is a pretty good baseline on your model. Okay, great. Just want to follow up, and it's in conjunction, Steve, with the detailed response that you gave to Doug's question when sort of hypothetically thinking about 2022. If I take what you just said on Egypt and the eight rigs would already have sort of maintained levels, and we'll just assume something north of that. Like Egypt post PSC would be growing. The North Sea you have previously talked about one rig, one platform can kind of maintain volumes at that 55,000-60,000 range. Obviously, first half of this year, due to the extended maintenance, you're a good bit below that. Just by default, the North Sea is going to be up a decent bit in 2022 versus 2021. The Permian, the base case sounds like it would be to add the third rig in the Permian that year in 2021, which gets that back to sort of a flattish or sustained sort of profile. Extern on am I just hypothetically thinking about those regions right? Yeah, I think directionally, John, that's about right. Most of the increased capital will be going to Egypt and a bit to the U.S. as well. Probably not a whole lot of additional capital in the North Sea, if any, but it'll be better production in the North Sea simply because of the downtime that we've had this year, which is both planned and unplanned, has been pretty material for second and third quarter. Again, I'll just remind you, John, that this is a hypothetical case. We're not trying to give any type of guidance or rolling out specific capital plans for 2022. That's still ahead of us for later this year. We'll talk about that some probably with third quarter earnings. No, understood. Yeah, it's the knucklehead analysts like us that'll be doing the speculating, but I appreciate all the answers, guys. Thank you, John. Your next question comes to the line of Bob Brackett with Bernstein Research. Good morning, all. Thanks for taking my question. I might be over-interpreting this, but the fact that the Maersk Developer is going to come back and appraise Keskesi South, does that mean that if you get a successful result on the well test, that's all the information you'll need on Sapakara to move it forward to FID? Would you expect more appraisal wells there? At this point, Bob, it clearly needs to come back. We need a flow test. I'll just say we still are appraising, and we may need more appraisal. I wouldn't read into it anything more than that. Okay. There's multiple opportunities to move forward in the appraisal pipeline. Correct. Okay. Thanks for that. You bet. Your next question comes to the line of Michael Scialla with Stifel. Good morning, everyone, and thank you for taking my question. This is actually Guillermo stepping in for Mike. I was wondering if you could provide some additional color on the CBP asset sale. Do you foresee to monetize more non-core assets like this one, and are there any other assets in the U.S. that you would want to increase your presence on? I think we've always looked at the portfolio as something that's kind of in flux. We're always looking for things that make sense to monetize. I'd characterize what we sold as pretty high water cuts. Higher lifting costs, some properties we've had in the portfolio for quite some time, and quite frankly, it's time to move those along the food chain to somebody else that will put more focus, attention on them, and quite frankly, a little cheaper cost structure. At this point, nothing major is planned. As always is the case, we like to report on these after we've done things, but we're constantly looking at a number of things. Nothing major planned at this point. That's helpful. Thank you. My follow-up, maybe on inflation. Are you seeing inflation in the drilling rates? You're planning to add that third rig. I was just wondering if you would foresee a more expensive rate on that additional rig? I think in general, on the inflation side, we had a lot of our key items secured for this year. I think you get into 2022, yet we are seeing some uptick in things that are around the commodities, people, things like that. I don't know anything particular, Dave, on rig contracts you want to comment on? Yeah. I think if you're looking for places for inflation, the completion side, pressure pumping and frack is where you'll see more inflation. We have that dialed into our forward. Anything that has to do with commodities, whether it's steel or on LOE with chemicals and diesel usage, you'll obviously price inflation there. When we look at our forward plan, we think we have it adequately captured. That's helpful. Thank you. That's it for me. Congrats on the quarter. Your next question comes on the line of Neal Dingmann with Truist. Oh, sorry about that. Was on mute. Hi, guys. Two quick ones if I could. First, just on sort of capital allocation, how you're thinking about things. My question is, I guess once you obviously start ramping up into Egypt, is that going to simultaneously then, would that take capital away from the U.S. and others? I'm just wondering, could you talk about the thoughts about when that happens, kind of how you view that activity versus what you're thinking domestically? I think we've got a pretty good base run that we're running right now, and that's where we've been. We've been pretty consistent. We did pick up the first two rigs early this year. We added a second rig in the Permian. We had a rig that drilled four wells in the Chalk in East Texas, in the U.S. North Sea's been pretty constant. Egypt, we've kind of moved from five or six rigs up to eight. In general, pretty level loaded, pretty constant, and I think it'll be pretty consistent as building blocks going forward. You will, post-modernization, see some changes to Egypt, but it will not impact cash flow or the capital in the other areas in a negative way. Okay. No, I assume that. It's good to hear that, John. Just a follow-up for you, Steve. To me, given what appears to be the strong transparency you continue to have with free cash flow, when do you all think about, I don't know, either call it notably or materially boosting dividends or free cash flow in addition to that your solid debt repayment program that you continue with? I think the first priority is exactly that. We came in to this year with too much debt, and we plan to pay debt down, as Steve's made very clear. I think once we make progress there, then you can start to think about the dividend. The first priority has been the debt, and clearly we're on a much faster pace there than we would've envisioned at the start of the year. Anything you want to add, Steve? No. Neal, I'd just say that, when do we think about it? We think about that all the time. We do realize it's important, and we need to do that. I'm sure with the amount of debt paydown that we're going to accomplish this year, we'll be talking about that in due course. Very good. It's certainly moving forward, not backwards. That's clearly received. Thank you all. Your next question comes on the line of Paul Cheng with Scotiabank. Hi. Good morning, guys. Good morning, Paul. John, two quick questions. Okay. First, the second quarter effective tax rate on the adjusted operating earnings seems low. Is there any one-off items in there, or what contributed to that seems like less than 30% effective tax rate? Secondly, I'm just curious, I think a lot of people will argue U.S. still have too many operators, in the U.S. shale. We don't need all the operators. Wondering that, for Apache, does it make sense that for you to try to find a company with the nearby land position and form a basket, John mentioned, and put everything together? Everyone still have the equity ownership, no one paying any equity premium to anyone. That by doing it this way, you can drive much better efficiency and cost improvement than individually perhaps that the company could be able to do. Is that something that you guys will entertain or you think that doesn't make sense for APA Corporation? Yeah. I'll let Steve address the effective tax rate question first, and then I'll come back to the second part. Paul, I think I understand the question around the effective tax rate. As you'll recall, we have put a 100% valuation allowance on the tax benefit of our net operating loss carry-forward in the U.S. on the balance sheet. You'd normally carry a deferred tax asset on the balance sheet, and we've put a complete valuation allowance on that, reducing that asset on the balance sheet to zero, even though we do have a pretty significant tax net operating loss carry-forward. What we do in periods of time like this, in the second quarter, when we have book income in the U.S., and we would normally recognize a tax expense. We release enough of that valuation allowance just to offset the tax expense for that quarter. You'll see the $60 million in our non-GAAP reconciliation from net income to adjusted earnings in the appendix in our supplement. That'll have the effect of lowering the effective tax rate quite a bit. I see. As long as we have discount commodity prices, and U.S. is earning a fair amount, we should assume the effective tax rate will be substantially lower than what, say, under a more normal tax rate would suggest. Correct. Okay. Good. Thank you. Paul, your second question, it really just boils down to value. I think the nice thing about our assets, we've got high working interest. We now have two rigs operating in the Permian. I think it boils down to scale, efficiency, and value added. In some areas, that could make a lot of sense. Some areas, it may not make sense. We're open to looking at things as always the case. Today, I think we like where we are. We like the pace. We like what we're doing. I think our wells are very competitive, and the performance is very strong. I think we're putting attention on the right assets within our portfolio today for us. Got you. Thank you. Your next question comes from the line of Gail Nicholson with Stephens. Good morning. want to discuss about Alpine. With the scenarios you laid out and keeping now equivalent volumes flat, is it fair to assume that Alpine potentially gets more capital in the 2024 timeframe? Can you just talk about the five DUCs that you're completing and how those compare to previous wells? Yeah. I'll let David touch on the DUC performance on those. As Stephen outlined, Gail, it's holding BOEs flat, but we actually are going to be growing oil and offsetting some of the gas in those cases. I'll let Stephen handle that, David, you can talk about the Alpine DUCs. Yeah, Gail, so just to be clear, again, we're not trying to say what exactly our capital program is going to be in 2022 and beyond. The hypothetical case that we used did not contain funding of additional drilling in Alpine High, so it's more oil-focused than gas-focused, thus gas volumes going down into the future, oil volumes going up. We look at that all of the time. Certainly, with gas and NGL prices improving in the recent months and could continue to improve, that'll be something that we will evaluate. As we finish up this year and roll into next year, we'll get into the actual capital program for 2022, which very well could include some capital for Alpine High. Yeah. Gail, on the performance, we've completed seven DUCs, just to level set, two early in the program and five more in the meat of the program. I think all the wells are meaningfully outperforming our expectations and prior well results for offset wells that we would've completed in the 2019 timeframe. We're very excited about the results. The most recent five, still early. They're producing. They've cleaned up, and they're producing well, but we want to continue to watch the performance curve before we spike the ball. Great. Just on the exploration front, there's a tremendous amount of potential in Suriname, but you've also had success in other areas like the Tertiary in the North Sea with Garten that you disclosed earlier this year. I'm just wondering how you guys are thinking about exploration outside of Suriname over the next couple of years. Yeah. Tracey, I'll let you. Hi, Gail. I think we are very excited about Suriname, as you mentioned, and I think we'll be looking for other opportunities. I think we are in a very opportunity-rich environment for exploration. It's early days. I've been with Apache now just right at two months. You'll hear more about that as we go forward. Definitely, we'll be looking at other opportunities. Great. Thanks, guys. An excellent quarter. Thank you. Your next question comes from the line of Leo Mariani with KeyBanc. Hi, guys. Just wanted to follow up a little bit on Suriname here. You guys mentioned that you're in the process of picking up a rig to drill a well, Apache operated on Block 53. Just wanted to get a little bit more information about that. Is this a mandatory well to hold the block? Is this a one-off exploration well as you folks see it? I guess is it just a short-term rig deal as a result? What would be the rough capital net to Apache to go and execute that? Leo, we've actually got one well required to continue to hold the block, and so we've got to spud a well by June of next year. We're excited about that. I think there's a lot of prospectivity in Block 53. In terms of where you look at where the costs are going today, well costs are probably going to be close to $100 million, would be my guess. For gross. We've got about 45% working interest in there. I'll let Tracey talk a little bit about what we see exploration-wise is we've got both slope and more of a deepwater setting on Block 53 like we do at Block 58. Yes. Leveraging on what John just said, it's certainly not a one-off exploration or seen as a mandatory well. I think what we've learned is an incredible amount with the exploration wells that we've drilled across 58. The petroleum systems within the basin continues right into Block 53. We're actually very excited, and we see some prospectivity that's very analogous to what we've been drilling in Block 58 and what we've just seen with some of the recent appraisal wells. I think we've learned a lot, and those learnings will be leveraged into what we see in Block 53 because we do see very analogous systems. Okay. That's helpful, color. I guess just given the substantial plans that are existing in Block 58, which I assume is going to involve at least a couple of rigs every year for the next several years. I know you have to get a well done by June, but can you give us a sense of, if you are successful here in Block 53, is this just another leg of the stool where this can be a block that has concurrent activity over the next couple of years in parallel with Block 58? How do you think about the success case here? The nice thing is we've got two partners here. We've got 45%, so I think it gives us a lot of optionality as we start to think about it. We are the operator of Block 53. We did do the joint venture and handed over operations in Block 58 to Total. I think it just builds out more optionality and more flexibility for us to look for different ways to continue to advance some longer-term, very meaningful programs. Okay, that's helpful. I guess just lastly on this potential for the third rig that you've talked about here. Obviously, you decided to add some activity in Egypt, and I think you guys have strongly alluded to the fact that a third rig can show up in the Permian. Just trying to get a sense of what's the decision point there? Is it really just about sustained higher commodity prices into year-end? If that occurs, is that third rig pretty much coming for next year to try to hold BOEs flat with oil up and gas down a little? No, we have not made a decision on a third rig. I want to make that really clear. It's not in the budget this year. I think it's important because we've been under-investing below sustaining levels to articulate what it would take. As Steve said in his prepared remarks, we're prioritizing debt paydown and the balance sheet first, which is why we've been under-investing, but the third rig would be required to get to a sustaining level in the U.S. We've got pretty attractive options for that. That's why that's framed that way. It's not a foregone conclusion that we're bringing it. We have not made that call, and capital remain at the $1.1 billion for 2021. Okay, thanks. Your next question comes on the line of Jeoffrey Lambujon with Tudor, Pickering, Holt & Co. Good morning, everyone. Thanks for taking my questions. My first one is just a follow-up on U.S. upstream. Obviously, throughout the first half of the year, U.S. volumes have been more than offsetting the planned and unplanned international downtime, which we see more about in the full-year guide as well, even net of the CBP sales. Just hoping you could talk more about what you've been seeing in non-Alpine high Permian now that we're through the first half of the year and how that might influence capital allocation within non-Alpine high Permian specifically. Yeah. Jeff, this is Dave. Good. Thanks for the question. We're seeing meaningful uplift in our performance on the Permian DUCs outside of Alpine as well. We're optimizing on a number of different variables. We're excited about that program. I think Stephen talked about it in his prepared remarks. When we look at our U.S. portfolio, we have multiple places that could compete for the capital for that third rig, and that would be the Chalk. It could be a third rig in the oily Permian and possibly the third rig in Alpine. We're evaluating those, but we're very excited about the performance that we've seen and the improvements that we continue. Got it. Thank you. Second, just to try on the Egypt PSC modernization and understanding you can't speak to specific terms, is there anything you can share at this time, maybe just on what mechanics are in flux that'll help to increase capital allocation to that region? No, I think you just got to look at it in terms of modernizing. We've got a lot of concessions. We'll be collapsing those, merge and joint ventures. There's a lot to do there administratively that's going to make it easier. It will effectively keep us from trapping capital. We're not in a position to elaborate more than that today. It's going through the approval process. We should be in a position to talk about it later this year for sure. Great. Thank you. Your next question comes from the line of David Heikkinen with Pickering Energy. Morning, guys. Thanks for the hypothetical framework. It is helpful, and we won't hold you to it for your budget. One of the things that we're curious about, and on the gas side, have you all thought about joining any of the oil and gas methane partnerships or certifying your natural gas or moving in any of that direction to really quantify the improvements you're showing around emissions? Yeah, I think we're a member of ONE Future. I think what our approach has been to take real tangible projects and steps that we can take. We're in the middle right now of working on our sustainability report, which will be coming out later in the year like we always do. We're monitoring all those things. I think the key for us is trying to focus on what are the material things we can do in our business that are going to lower those emissions and drive performance, right? Those are the things we're focused on. As you think about your operations globally, would you move towards quantifying carbon equivalent emissions per barrel for the North Sea, Egypt, or your U.S. operations? Yeah, I think we'll stay tuned and monitor where things are going. For us, we recognize we need to continue to lower our footprint. We need to be in a position and continue to monitor and measure those and take those steps. We'll just be determining what's the best way to show it and the best way to quantify it and also how to attack it. In the end, it's about lowering emissions. Okay. Thanks, guys. At this time, there are no further questions. I'll turn the call back to John Christmann. Thank you. Before ending today's call, I'd like to leave you with three points, the first 2 of which are important catalysts. First, we are very encouraged with the progress in Suriname and look forward to having further results later this year. Second, the PSC modernization in Egypt will have an immediate positive impact for both the country and APA. We are very pleased with how things are progressing. Finally, the free cash flow capacity of our base business is robust and sustainable. This will materialize in returns to investors. Thank you for participating in our call today. Operator, over to you. Thank you, ladies and gentlemen. That concludes this conference call. You may now disconnect.